1. Field of the Invention
The invention relates to treating well bores drilled in oil-base mud. More particularly, it relates to an emulsion-breaking formulation for use in treating well bores drilled in oil-base mud, preferably non-ecotoxic and optimally compatible with formation fluids, which comprises at least one constituent selected from non-ionic amphiphilic compositions obtained by reacting at least one vegetable oil polymerized with at least one aminoalcohol and alkyl esters (for example C1 to C8) of fatty acids derived from natural, vegetable or animal oils; optionally, at least one wetting agent selected from anionic surfactants; and optionally, at least one solvent (or diluent); said emulsion-breaking formulation being used in an organic base to limit phenomena of emulsion formation in situ and re-saturation of the well edges with an aqueous phase. The invention also concerns formulations of the same type weighted with mineral fillers.
An oil-base formation is damaged when a well is shown to be less productive than well analysis tests predict. The mechanisms of formation damage depend on the type of reactions produced between the well fluid, and the formation and rock fluids under operating conditions (pressure and temperature of the zone and the mud). An alteration in the producing formation close to the well is due to deleterious interactions between the formation fluids and the foreign fluids introduced. If the well fluids are shown to be responsible for the damage, a chemical treatment is necessary to restore the characteristics of the reservoir. It has to cause the destruction of the external and/or internal cake and clean the damaged zone at the well edges. Such a treatment may or may not be combined with an acidic matrix treatment.
As a general rule, oil-base well fluids generate little filtrate, have good rheological properties and form a thin, permeable cake. In contrast, they contain chemical additives (surfactants) charged with emulsifying the water into the form of droplets in the continuous oil-base phase and with making the solid particles used as a weighting agent or viscosifying agent wettable by the oil. Such surfactants, in a large excess of concentration in the fluid to maintain the stability of the reverse emulsion, can penetrate into the formation with the filtrate.
In particular, three types of damage can be envisaged with oil-base fluids:                the formation of an emulsion in the reservoir, resulting from interactions between the filtrate from the oil-base mud (which principally contains oil and surfactants) and the reservoir fluids (brine and oil). The emulsifying agents introduced in excess into the formulation can come into contact with the formation. Substantial shearing at the constriction caused by the pores in the presence of an emulsifying agent can lead to the formation of a very stable, highly viscous emulsion causing a reduction in the effective mobility of the hydrocarbons present;        an alteration in the initial wettability of the reservoir rock. The emulsifying type products generally transform the initially water-wettable rock into a rock with intermediate wettability, which may even be oil-wettable, which can cause a modification in the oil permeability and thus reduce the mobility of the oil; and        deposition of fine mobile particles in the pores (reduction of absolute permeability).        
The chemical composition of the filtration cake must be carefully considered when designing treatment fluids. The cake is principally constituted by emulsified water droplets that act as colloidal particles and combine with solid particles in suspension in the fluid to form a cake. The stability of the emulsion, the type and nature of the solids influences both the fluid loss and the cake's filtration properties. The choice of treatment product must take into account the parameters necessary for washing the cake and leaching of the formation.
The envisaged treatment concerns:                dissolving or dispersing the weighting agents present in the cake;        and attack of the additives contained in the filtrate.        
Thus, the treatment must be adapted to the type of mud used. The principal parameters to be considered are:                the type of damage and its extent;        the characteristics of the reservoir (porosity and permeability);        the type of formation (nature of rocks and acid solubility);        possible contaminants (water, mud—water-base mud and oil-base mud, cements, bacteria);        the compatibility of the treatment fluid with the contaminants;        the bottom pressure and temperature;        the treatment time; and        the physical limitations of the well equipment.        
2. Description of the Prior Art
An improvement in the design of a drilling fluid aimed at reducing damage can be completely ruined by using an unsuitable procedure and/or cleaning fluid. The solutions for treating cakes and oil-base mud in current use are in the aqueous form and generate considerable additional damage, and can even block the well. A number of examples of treating well bores using surfactants used in the aqueous phase can be found in the literature (U.S. Pat. Nos. 4,681,165, 4,595,511 4,681,164 and 5,110,487). The use of oil-base surfactants to break emulsions has been reported (U.S. Pat. Nos. 5,614,101, 5,256,305 and 4,416,754), but the aim was not an application to oil field production.